U.S. patent application number 12/641887 was filed with the patent office on 2011-06-23 for retrieval method for opposed slip type packers.
Invention is credited to Marion Dewey Kilgore.
Application Number | 20110147013 12/641887 |
Document ID | / |
Family ID | 44149481 |
Filed Date | 2011-06-23 |
United States Patent
Application |
20110147013 |
Kind Code |
A1 |
Kilgore; Marion Dewey |
June 23, 2011 |
Retrieval Method For Opposed Slip Type Packers
Abstract
A method is provided which releases and retrieves an opposed
slip downhole tool by reducing the compressive forces on the
sealing elements prior to unsetting the slip assemblies. Further,
the method does so without damaging the slip assemblies. The method
provides for the retrieval of the entire downhole tool including
all of its component parts, requiring but a single trip within the
wellbore. When the tool is to be retrieved, the sealing element is
disengaged from the casing by relaxing the compression forces on
the sealing element. Then the slip assemblies are disengaged from
the casing such that the slip assemblies are no longer in gripping
engagement with the casing. The tool is then retrieved from the
wellbore. The step of disengaging the sealing assembly can be
performed by radially contracting the sealing element with or
without longitudinally expanding the sealing element.
Inventors: |
Kilgore; Marion Dewey;
(Terlingua, TX) |
Family ID: |
44149481 |
Appl. No.: |
12/641887 |
Filed: |
December 18, 2009 |
Current U.S.
Class: |
166/387 |
Current CPC
Class: |
E21B 33/1285 20130101;
E21B 33/1295 20130101; E21B 33/1293 20130101 |
Class at
Publication: |
166/387 |
International
Class: |
E21B 33/12 20060101
E21B033/12 |
Claims
1. A method of utilizing an opposed-slip type downhole tool in a
subterranean wellbore having a casing, the method comprising the
steps of: positioning the tool in a subterranean wellbore, the tool
having an upper slip assembly and a lower slip assembly positioned
on opposite sides of a sealing assembly, the sealing assembly
having at least one compressible, annular sealing element; then
setting the tool in the wellbore by radially expanding the slip
assemblies into gripping engagement with the casing, and by
longitudinally compressing and radially expanding the sealing
element into sealing engagement with the casing; then disengaging
the sealing element from the casing by relaxing the compression
forces on the sealing element; then disengaging one of the slip
assemblies from the casing such that the slip assembly is no longer
in gripping engagement with the casing; and then retrieving the
tool from the wellbore.
2. The method of claim 1, wherein the step of disengaging one of
the slip assemblies comprises disengaging the upper slip
assembly.
3. The method as in claim 2, further comprising the step of
disengaging the lower slip assembly from the casing after the step
of disengaging the upper slip assembly from the casing.
4. The method as in claim 1, wherein the step of disengaging the
sealing element includes radially contracting the sealing
element.
5. The method as in claim 1, wherein the step of disengaging the
sealing element includes longitudinally lengthening the sealing
element.
6. The method as in claim 1, wherein the step of disengaging the
sealing element further comprises moving a sealing element retainer
to reduce the compression forces on the sealing element.
7. The method as in claim 6, wherein the sealing element retainer
is moved longitudinally, the longitudinal movement of the sealing
element retainer relaxing the longitudinal compression on the
sealing element.
8. The method as in claim 7, wherein the sealing element retainer
moves longitudinally upward during the step of disengaging the
sealing element.
9. The method as in claim 8, wherein the sealing element retainer
is an annular member in sliding engagement with a mandrel of the
tool, the sealing element retainer connected to the upper wedge
assembly by a releasable connection, and wherein the sealing
element retainer is released to move with respect to the upper
wedge assembly during the step of disengaging the sealing
element.
10. The method as in claim 9, wherein the releasable connection
includes a toothed, collapsible C-ring, the teeth of which engage a
corresponding toothed portion of the upper wedge assembly, the
C-ring cooperating with and collapsing into a reduced-diameter
portion of the outer surface of the tool mandrel during the step of
disengaging the sealing element.
11. The method as in claim 6, wherein the sealing element has an
interior surface, and wherein the sealing element retainer provides
compression force, when the tool is set, acting on the interior
surface of the sealing element.
12. The method as in claim 11, wherein the sealing element retainer
is moved longitudinally during the step of disengaging the sealing
element, the movement of the retainer relaxing the compression
force acting against the interior surface of the sealing
element.
13. The method as in claim 6, wherein the tool further comprises a
mandrel, and wherein the sealing element retainer is a portion of
the tool mandrel.
14. The method as in claim 13, wherein the tool mandrel has a
reduced-diameter portion which is moved into alignment with the
sealing element during the step of disengaging the sealing element,
thereby reducing the compression force on the sealing element and
allowing the sealing element to relax.
15. The method as in claim 1, wherein the tool includes a tool
mandrel, and further comprising the step of cutting the
mandrel.
16. The method as in claim 1, wherein the tool includes a mandrel
and a sleeve connected to one another by a releasable connection,
and wherein the mandrel and sleeve are released to move relative to
one another during the step of disengaging the sealing element.
17. The method as in claim 1, wherein the sealing assembly includes
multiple sealing elements.
18. The method as in claim 2, wherein the upper slip assembly is a
barrel slip assembly.
19. The method as in claim 18, wherein the step of disengaging the
upper slip assembly includes the step of moving lugs into contact
with a portion of the upper slip assembly and moving the upper slip
assembly upward, thereby disengaging the upper slip assembly from
the wellbore casing.
20. The method as in claim 1, wherein the step of setting the tool
further comprises setting the tool using a hydraulic assembly.
Description
FIELD OF INVENTION
[0001] The invention relates generally to equipment utilized in
conjunction with subterranean wells and, more particularly, to
retrieving packers or other downhole tools having opposed slip
assemblies to secure the tool in a cased wellbore. This invention
would be especially useful with high performance tools designed for
use in high pressure and high temperature environments.
BACKGROUND OF THE INVENTION
[0002] Current practices used to unset and retrieve opposed slip
type packers and other tools, such as plugs, particularly those
used in extreme pressure and temperature environments, have not
proven to be efficient or reliable due to various limitations.
Further, the methods for retrieving such tools often result or
require the destruction of the tool or parts thereof, such as by
drilling, milling and the like.
[0003] Various patents describe mechanisms for setting, unsetting
and retrieving downhole tools such as packers, including U.S. Pat.
Nos. 4,151,875 to Sullaway, 5,224, 540 and 5,271,468 to Streich,
5,727,632 to Richards, 7,080,693 to Walker, and 7,198,110 to
Kilgore, all of which are herby incorporated for all purposes.
[0004] It is desirable to provide a tool release and retrieval
method which results in a more efficient and reliable retrieval
process. Further, it would be desirable to retrieve the entire
downhole tool, including all of its component parts. Further, it
would be desirable to release and retrieve the entire tool with a
single trip within the wellbore.
SUMMARY OF THE INVENTION
[0005] A method is described, which provides for the release and
retrieval of an opposed slip type down hole tool by reducing the
compressive forces on the sealing elements prior to unsetting the
upper slip assembly. Further, the method does so without damaging
the slip assemblies. The method provides for the retrieval of the
entire downhole tool, including all of its component parts,
requiring but a single trip within the wellbore.
[0006] A method is described for utilizing an opposed-slip type
downhole tool in a subterranean wellbore having a casing. The tool
is positioned in a subterranean wellbore having a casing. The tool
has upper and lower slip assemblies positioned on opposite sides of
a sealing assembly. The sealing assembly has at least one
compressible, annular sealing element. The tool is then set in the
wellbore by radially expanding the slip assemblies into gripping
engagement with the casing, and by longitudinally compressing and
radially expanding the sealing element into sealing engagement with
the casing. When the tool is to be retrieved, the sealing element
is disengaged from the casing by relaxing the compression forces on
the sealing element. Then the slip assemblies are disengaged from
the casing such that the slip assemblies are no longer in gripping
engagement with the casing. The tool is then retrieved from the
wellbore.
[0007] The step of disengaging the sealing assembly can be
performed by radially contracting the sealing element with or
without longitudinally expanding the sealing element.
[0008] In a preferred method, the tool includes a sealing element
retainer assembly having a sealing element retainer, which is moved
with respect to the sealing element to reduce the compression
forces on the sealing element. The sealing element retainer can be
moved longitudinally or otherwise. Movement of the sealing element
retainer results in relaxation of, or reduction of compressive
forces in, the sealing element. In a preferred embodiment, the
sealing element retainer is an annular member in sliding engagement
with a mandrel of the tool, the sealing element retainer connected
to the upper wedge assembly by a releasable connection. The sealing
element retainer is released to move with respect to the upper
wedge assembly during the step of disengaging the sealing element.
In the exemplary embodiment, the releasable connection includes a
toothed, collapsible C-ring, the teeth of which engage a
corresponding toothed portion of the upper wedge assembly. The
C-ring cooperates with and collapses into a reduced-diameter
portion of the outer surface of the mandrel during the step of
disengaging the sealing element.
[0009] In an alternative embodiment, the sealing element is relaxed
by allowing radial contraction without allowing longitudinal
expansion. The sealing element retainer is moved longitudinally
during the step of disengaging, the movement of the retainer
relaxing the compression force acting against the interior surface
of the sealing element by aligning a reduced-diameter portion of
the mandrel with the sealing element, thereby reducing the
compression force on the sealing element and allowing the sealing
element to relax.
[0010] Alternate embodiments are described and these and other
features, advantages, benefits and objectives of the present
invention will become apparent to one of ordinary skill in the art
upon careful consideration of the detailed description of
representative embodiments of the invention herein below and the
accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 is a cross-sectional view of a cased wellbore
extending through a subterranean zone with a tool embodying the
principles of the invention in a set position in the wellbore;
[0012] FIGS. 2A-2E are partial cross-sectional views of an opposed
slip type tool of an embodiment of the invention in a run-in
position;
[0013] FIGS. 3A-3E are partial cross-sectional views of an opposed
slip type tool of an embodiment of the invention in a set
position;
[0014] FIGS. 4A-4F are partial cross-sectional views of an opposed
slip type tool of an embodiment of the invention in an unset or
released position; and
[0015] FIG. 5 is cross-sectional view of an alternate embodiment of
an opposed slip type packer of an embodiment of the invention.
[0016] In the following description of the tool and other apparatus
and methods described herein, directional terms, such as "above",
"below", "upper", "lower", etc., are used only for convenience in
referring to the accompanying drawings. Additionally, it is to be
understood that the various embodiments of the present invention
described herein may be utilized in various orientations, such as
inclined, inverted, horizontal, vertical, etc., and in various
configurations, without departing from the principles of the
present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0017] While the making and using of various embodiments of the
present invention are discussed in detail below, a practitioner of
the art will appreciate that the present invention provides
applicable inventive concepts, which can be embodied in a variety
of specific contexts. The specific embodiments discussed herein are
illustrative of specific ways to make and use the invention and do
not delimit the scope of the present invention.
[0018] FIG. 1 is a cross-sectional view of a wellbore 2 extending
through a production zone 6 of a subterranean formation 9. The
wellbore 2 has a casing 4 which has been cemented 7 in place.
Perforations 8 extend into the production zone 6. An exemplary tool
10 of the invention is shown in a downhole position in the
wellbore, in a set position in engagement with the casing 4.
[0019] Representatively illustrated in FIGS. 2-4 is a
cross-sectional view of a downhole tool 10, which embodies
principles of the present invention. As explained in detail herein,
FIGS. 2A-E show the tool 10 in a run-in position, FIGS. 3A-E show
the tool 10 in a set position, and FIGS. 43A-F show the tool in a
released or un-set position.
[0020] The tool 10 described herein is an example of an "opposed
slip" type well tool which may be run, set, unset and retrieved in
a wellbore having a casing using the principles of the invention.
The tool 10 is a well tool of the type which, when set, dually
grips the wellbore preventing either upward or downward tool
movement. The opposed upper and lower slip assemblies function to
anchor the tool against movement in both axial directions. The
gripping or anchoring function is performed by the upper and lower
slip assemblies 20 and 60 when in the set position, as seen in
FIGS. 2A-E, wherein the slip assemblies are in a radially expanded
set position to engage the casing of the wellbore. Further, the
opposed slip type tool positions the upper and lower slip
assemblies 20 and 60 on opposite sides of the sealing assembly, or
packer element assembly, 40. The sealing assembly 40, when in the
radially expanded set position, sealingly engages the casing of the
wellbore preventing fluid flow longitudinally between the casing
and the tool mandrel 12.
[0021] Consequently, the use of the term "opposed slip type tool"
as used herein is limited to downhole tools having an upper and
lower slip assembly on opposite sides (above and below) a sealing
assembly. The tool 10 is illustrated as a packer, however, the
invention applies equally to all opposed slip type tools having
slip assemblies above and below a sealing assembly, including
plugs, valves, etc., as will be apparent to one of skill in the
art. The invention lies in the methods and apparatus for releasing
and retrieving the tool as claimed, rather than in the function of
the tool when set in the wellbore.
[0022] The terms "uphole" and "upward" refer to the direction
toward the wellbore surface. The terms "downhole" and "downward"
refer to the direction of away from the wellbore surface. While it
is anticipated that the surface is generally upward from any
downhole location, the tool may be utilized in a deviated or
horizontal wellbore, in which case the terms refer to the
directions indicated rather than relative vertical placement.
[0023] When in the set position, compressive forces are "trapped"
in the sealing assembly 40. That is, compressive forces are applied
to the sealing assembly during the setting process in order to
radially expand the sealing elements 42 into sealing engagement
with the wellbore. These compressive forces remain acting on the
sealing assembly while the tool is in the set position, the
relative spacing of the upper and lower slip assemblies maintaining
the sealing assembly in a radially expanded and longitudinally
shortened position. After being set in the wellbore, and prior to
retrieval, the invention enables the compressive forces on the
sealing assembly 40 of the tool 10 to be reduced or relaxed before
unsetting the slip assemblies 20 and 60.
[0024] This method of relaxing the sealing assembly before release
of the slip assemblies results in a more reliable and efficient
process of retrieval of the downhole tool. The methods included in
the invention also permit the full retrieval of the packer and all
of its components as a single unit. The methods also permit, but do
not require, the release and retrieval of the well tool in a single
trip within the wellbore.
[0025] As used herein the term "set" is used to refer to an
operation producing a gripping and sealing engagement between the
well tool and the casing of the wellbore. The "set position" is
used to refer to the tool when in a position having the slip
assemblies in a radially expanded position in gripping engagement
with the casing and the sealing assembly radially expanded and in
sealing engagement with the casing. The terms "release" or "unset"
are used to refer to an operation, which moves the tool out of
gripping and sealing engagement with the casing of the wellbore to
permit removal or retrieval of the tool from the wellbore. While it
is preferable that the unsetting of the tool will move the tool out
of all contact with the casing, it is recognized that this may not
always be the case. If the wellbore is horizontal, or other than
vertical, the tool may still contact the casing as it lies in the
wellbore. Further, the sealing assembly, once expanded, may not
radially reduce in diameter sufficiently to prevent all contact
with the casing. However, the sealing assembly must be unset, or
radially contract, enough to allow relatively easy removal from the
well. The term "nm-in position" refers to the tool when in an
initial position for running the tool into the wellbore, wherein
the slip assemblies are radially contracted and the sealing
assembly radially contracted. Similarly, the term "unset position"
or "released position" refers to the tool when after being in the
set position, is in a position with the slip assemblies radially
contracted and the sealing assembly radially contracted.
[0026] Turning to FIGS. 2A-E, the tool 10 includes a mandrel 11 on
which essentially all other components are carried or assembled.
The tool 10 includes an upper sub 16, an upper slip assembly 20, an
upper wedge assembly 30, sealing assembly 40, lower wedge assembly
50, lower slip assembly 60, packer element retaining assembly or
"prop" assembly 70, setting assembly 100 and lower sub 18. The
major components described above make up the primary components of
the tool 10 according to an embodiment of the present invention.
More details of the tool 10, its methods of operation, and various
methods of reducing the compressive forces on the packer sealing
elements 42 prior to unsetting the slip assemblies 20 and 60 are
provided below.
[0027] In FIGS. 2A-E, the tool 10 and its various components are
shown in their run-in positions, that is, the position when the
tool 10 is run-in or lowered into a well in preparation for setting
the tool 10 in the wellbore casing. The various components of the
tool 10 are positioned to allow lowering into the casing without
interference. The upper and lower slip assemblies 20 and 60 have
not yet been radially expanded and are at a first diameter smaller
than when in the set position, discussed below. Similarly, the
sealing assembly 40 has not yet been radially expanded into a set
position and is at a first reduced diameter. The setting assembly
100 has not been actuated.
[0028] The mandrel 11 is shown threadedly connected to an upper sub
16 and a lower sub 18. Alternately, the tool and subs can be formed
as a single solid piece. The upper sub 16 is designed for
connection to a tubing string, coiled tubing or the like as is
known in the art. Further or alternately, the upper sub is
configured to receive and releasably connect to a stinger, setting
tool, actuating or operating tool, hydraulic actuator, or other
well tool as is known in the art. The lower sub 18 can also be
configured as desired.
[0029] The upper and lower slip assemblies 20 and 60 have upper and
lower slip elements 22 and 62, respectively. In the embodiment
shown, the slip elements are part of a circumferentially
continuous, axially-slotted, barrel-type slip of the type known in
the art. However, it is to be clearly understood that the slip
assemblies may be differently configured without departing from the
principle of the present invention. For example, the slip elements
22 can be comprised of a plurality or series of slip elements which
are independent and separated from one another, or partially
segmented and movably joined to one another, circumferentially
discontinuous, divided, slotted, etc. The slip assemblies may
include further elements not shown, such as retaining rings or
devices, to maintain the slips in the run-in position until setting
the tool. The slip assemblies 20 and 60, as shown have shear
mechanisms 26 and 66, to maintain the slip assemblies in their
run-in position. The shear mechanisms, here pins, are sheared as an
initial step in setting the tool to allow relative longitudinal
motion between the slip elements and the mandrel. Other methods of
maintaining the slip assemblies in a run-in position are known in
the art and may be employed. The upper slip assembly 20 further
includes an upper slip support 25, in this case an enlarged portion
of the lower end of the upper sub 16. The slip support 25 abuts the
upper end of the upper slip elements 22, maintains the relative
positions of the assemblies during run-in, and communicates setting
force during setting. In this case, the upper slip support 25 does
not move relative to the mandrel 12 during setting. Other slip
support mechanisms are known in the art and may be used.
[0030] The slip assemblies 20 and 60 have a plurality of
longitudinal slots 24 and 64, respectively. The slots 24 of the
upper slip assembly 20 cooperate with lugs 14, which are integrally
formed on the mandrel 12 and extend radially from the mandrel body
into the slots. Each of the slots 24 has a closed upper end 27,
which the lugs 14 will contact during the unsetting or releasing
step. As the mandrel 12 is moved longitudinally during the
unsetting or disengaging process, the lugs move longitudinally with
respect to the upper slip assembly 20. The lugs 14 contact the
upper ends 27 of the slots 24 of the barrel slip and unset the slip
assembly. That is, the slips 22 are pulled off of the wedges of the
wedge assembly 30. The slip assembly then radially contracts,
thereby disengaging with the casing wall. The tool 10 is designed
such that the upper slip assembly is not unset or disengaged until
after the sealing assembly is disengaged from the casing. The lugs
14 move longitudinally along the slots 24 as the groove 78 on the
mandrel is moved into alignment with the release mechanism 75, as
described below, but do not contact the upper ends of the slots 24
until after the groove and release mechanism are aligned and the
prop member 72 telescopes with respect to the upper wedge assembly
30. Thus, the upper slip assembly is not disengaged until after the
sealing assembly is disengaged.
[0031] Each of slip elements 22 and 62 contains a series of
serrated outwardly protruding teeth 28 and 68, respectively,
thereon for gripping the casing wall or other conduit within the
wellbore. The teeth or gripping structures 28 and 68 of the slip
assemblies 20 and 60 may be of any design known in the art, such as
integrally formed on the slip elements, separately attached to the
assemblies (such as "button slips"), etc. Incorporated herein by
reference for all purposes is U.S. Pat. No. 5,224,540 to Streich
which describes and refers to various setting mechanisms, slip
configurations, slip supports, and teeth among other things
[0032] The upper wedge assembly 30 is carried on the mandrel 12.
The upper slip assembly 20 and the upper wedge assembly 30 have
cooperating sloped surfaces 29 and 32, which cause the upper slip
assembly 20 to expand radially as the upper wedge assembly 30 is
moved longitudinally relative to the upper slip assembly 20. To
"expand radially", as used herein in reference to the upper 20 and
lower 60 slip assemblies, means to expand their outer diameters
rather than suggesting a volumetric increase of the components. The
radial expansion of the upper slip assembly 20 causes their
gripping surfaces 28 to come into contact with the interior surface
of the wellbore casing. With sufficient radial expansion, the upper
slip assembly 20 becomes grippingly engaged with the casing,
preventing upward movement of the tool 10 in the wellbore.
[0033] Similarly, the lower wedge assembly 50 is carried on the
mandrel 12. The lower slip assembly 60 and the lower wedge assembly
50 have cooperating sloped surfaces 62 and 52, which cause the
lower slip assembly to expand radially as the lower wedge assembly
is moved longitudinally relative to the lower slip assembly. This
radial expansion causes the lower slip assembly 60 to become
grippingly engaged with the wellbore casing as described with
respect to the upper assembly above. The lower slip support 65 is
shown as abutting the lower end of the lower wedge assembly 60. The
slip support, as described above, is utilized to maintain the wedge
and slip assemblies in position during run-in and to communicate
setting force to the wedge and slip assemblies during setting. In
this case, the lower slip support 65 moves upward relative to the
mandrel 12 during the setting process. The lower slip support 65 is
shown having a shearing mechanism 26 to hold the slip support in
place until the setting process is begun.
[0034] As shown in FIG. 2A, the sealing assembly 40 is mounted
circumferentially on the mandrel 12 between the upper 20 and lower
60 slip assemblies. Also shown in FIGS. 2A-E, the sealing assembly
40, or packer element assembly, includes a plurality of sealing
elements 42a-c. These sealing or packer elements may typically be
made of an elastomeric material such as rubber but may be
constructed of other materials familiar to those skilled in the
art. It is to be understood that the sealing assembly 40 may have
one or more sealing elements 42. Further, the sealing assembly 40
is shown having deformable support members 44, which function as
anti-extrusion rings when in the set position.
[0035] In the run-in position, the sealing elements 42 are carried
on the packer element assembly in an unexpanded position having a
radial diameter smaller than when in the set position. In the set
position, as shown in FIGS. 3A-E, the sealing elements 42 are
expanded outward radially by the relative movement of the upper and
lower wedge assemblies toward one another. This longitudinal
shortening of the sealing assembly 40 results in simultaneous
radial expansion of the sealing assembly. The sealing elements 42
are radially expanded into sealing engagement with the wellbore
casing. This sealing engagement may not provide an absolute seal
but does prevent any significant fluid flow between the outside of
the sealing assembly and the interior surface of the wellbore
casing at typical, or even severe, downhole temperatures and
pressures. The sealing elements 42 effectively seal the annular
space between the mandrel 12 and the casing.
[0036] FIGS. 3A-E depict the packer 10 in the "set" position.
Because the opposed slip assemblies grip and act in opposite
directions, they tend to move closer together during wellbore use,
especially with reversals in the differential pressure across the
tool. This "cinching up" is beneficial in that it increases the
gripping forces on both the slip assemblies and the sealing forces
on the sealing elements, thus holding the tool more firmly in the
set position. The cinching movement, however, also increases the
magnitude of the compression forces in the sealing elements 42. The
movement also increases the tension in the portion of the wellbore
casing between the two slip assemblies 20 and 60. The compression
forces within parts of the tool 10 and tension forces within parts
of the wellbore casing make the unsetting and retrieval of the
packer more difficult.
[0037] Once the tool 10 has been lowered into the desired position
in the wellbore, that is, a selected distance from surface, the
tool 10 is set or moved into a set position, as seen in FIGS. 3A-E,
by actuating the setting assembly 100. The setting assembly 100 is
actuated to move the tool components into their set positions. The
setting assembly 100 is shown as a hydraulic setting assembly
formed as part of the tool 10 at its lower end. The setting
assembly 100 and method of setting will not be described in detail
herein since they are generally known and understood in the art.
The setting assembly 100 can be an electrical, mechanical,
electro-mechanical, or hydraulic setting assembly (as shown), or of
other type as known in the art. The hydraulic setting assembly
shown is used in conjunction with an actuator tool, not shown,
which would typically be connected above the tool 10. Such an
actuator can be of any design known in the art, such as but not
limited to Downhole Power Units, electric line power units,
gas-powered units, mechanical and electromechanical setting tools,
etc. A mechanical setting assembly can be actuated by the
weight-down of the tubing string, or by utilizing a setting tool
connected to the tool mandrel for pulling upward on the mandrel to
set the packer. The type and details of the setting assembly are
not critical to the invention and the tool 10 can be modified as
desired from the shown embodiment to allow for the use of different
setting tools and mechanisms. The setting assembly shown in the
embodiment in FIGS. 2-4 includes a piston 102, which moves relative
to the mandrel 12 when fluid flows through inlet port 104 into and
filling fluid chamber 106.
[0038] This invention provides a method to improve the reliability
and efficiency of unsetting and retrieving the packer 10 by making
it possible to reduce, relieve, or relax the compressive forces
within the sealing assembly 40. The compressive forces on the
sealing elements 42 are relaxed or released before attempting to
unset either slip assembly. To this end, the tool 10 further
includes a prop assembly 70 or sealing element retainer assembly
70, as seen in FIGS. 2-4. The prop assembly 70 includes a prop
member 72, which moves relative to the sealing assembly 40 during
the step of releasing or relaxing the sealing elements 42 of the
sealing assembly 40 as will be described further herein. The prop
assembly 70 further includes a releasable connector assembly 74
which operates to maintain the prop assembly components in run-in
and set positions, then allow movement of the assembly parts during
the process of relaxing the sealing elements 42.
[0039] A preferred embodiment is shown in FIGS. 2-4. The prop
assembly 70 has a prop member 72, which abuts the upper end of the
sealing element assembly 40. The prop member 72 is an annular
sleeve, slidably mounted for longitudinal movement on the exterior
surface of the mandrel 12. The prop member at its upper end abuts a
releasable connector assembly 74. [The releasable connector
assembly 74 includes a release mechanism 75. In the embodiment
shown in FIGS. 2-4, the release mechanism is a collapsible C-ring
having a threaded or toothed portion 76, which cooperates with a
threaded or toothed portion 34 of the upper wedge assembly 30]. In
the run-in position, seen in FIG. 1, the toothed portion of the
collapsible C-ring 75 is in engagement with the toothed portion of
the upper wedge assembly. The upper wedge assembly and prop
assembly are thus connected and fixed in relative position to one
another.
[0040] In the set position, as seen in FIG. 3, the sealing element
retainer assembly 70 maintains its relative position with the upper
wedge assembly 30 due to the interlocking toothed portions 76 and
34. Note, however, that both the upper wedge assembly 30 (after
shearing of pin 26) and the prop assembly are free to move relative
to the mandrel 12 during the setting process.
[0041] In the unset or released position, seen in FIG. 4, the
releasable connector assembly 74 has released. The collapsible
C-ring has collapsed into cooperating groove 78 in the mandrel 12
due to the relative motion of the mandrel 12 with respect to the
prop assembly 70. Alternately, the groove 78 can be in a sleeve or
other movable member of the tool designed to cooperate with the
release mechanism. With the C-ring collapsed to a smaller diameter
position in the groove 78, the cooperating toothed portions 34 and
76 are no longer in contact. In turn, this allows the prop member
72 to move with respect to the upper wedge assembly 30 and the
mandrel 12. The prop member 72, as seen in FIG. 4, moves
longitudinally with respect to the upper wedge assembly and
telescopes with respect to a member of the upper wedge assembly 40.
The relative movement of the prop member 72 with respect to the
mandrel 12 and with respect to the sealing assembly allows the
sealing elements 42 to longitudinally expand and radially contract,
thereby releasing or relaxing the compression forces acting on the
sealing elements 42.
[0042] The releasable connector assembly 74 can be of other design
without departing from the spirit of the invention. For example,
the releasable connector assembly can include a collet assembly
with cooperating collet fingers and grooves or lips. The releasable
assembly can further be a shearing mechanism, such as shear pins or
rings, or the like. Other releasable connectors can be utilized as
will be recognized by those of skill in the art.
[0043] In this preferred embodiment, the prop assembly has a prop
member, which moves longitudinally upward to allow the sealing
elements and assembly to relax. As those skilled in the art will
recognize, the assembly can be arranged such that downward movement
will affect relaxation of the sealing elements. Further, other
movement and mechanical designs for the prop member can be
employed. The key is that the prop assembly moves to allow the
sealing assembly to relax. The prop assembly can allow the sealing
elements to expand longitudinally, thereby contracting radially, as
seen in the embodiment in FIGS. 2-4. Alternately, the prop assembly
can allow for radial contraction of the sealing elements without
allowing change in the length of the sealing assembly. Such a
configuration is explained below with respect to FIG. 5. The
movable prop member can be located above or below the sealing
assembly, or can be located radially inward from the sealing
elements. Other arrangements will be apparent to one skilled in the
art.
[0044] The preferred embodiment described in detail above is but
one method of reducing the compressive forces in the sealing
elements before tool retrieval. In the above method, these
compressive forces are reduced by the use of a sealing element
retainer member 72 held in an extended position by a releasable
connector assembly. The releasable connector is released by
relative movement of the mandrel, which aligns a groove 78 with the
release mechanism 75. In turn, this allows the prop member 72 to
move longitudinally, thereby reducing the compression forces on the
sealing elements. The sealing elements are free to longitudinally
lengthen or expand, which results in radial contraction of the
elements.
[0045] In another embodiment of this invention, illustrated in FIG.
5, the reduction in compressive forces in the sealing elements 42
is achieved by aligning a reduced diameter section 79 of the
mandrel 12 with the sealing elements 42. In this case, the prop
member 72 is a portion of the mandrel 12 which moves longitudinally
with respect to the sealing elements 42 during the unsetting
process. As the prop member 72, or mandrel portion, is moved
relative to the sealing assembly 40 during the unsetting process, a
reduced diameter portion 79 of the mandrel 12 is moved into
longitudinal alignment with the sealing elements 42. With the
additional radial space made available, the compression forces on
the sealing elements 42 are reduced and the sealing elements
contract radially to an unset position such that they are no longer
in sealing engagement with the casing. The reduced diameter portion
of the mandrel can alternately be provided on a separate movable
member of the tool, such as on a sliding sleeve or the like.
[0046] Also illustrated in FIG. 5, is another type of releasable
connector assembly 74. A sleeve 77 is mounted exterior to the
mandrel and maintained in position with respect to the mandrel 12
by a release mechanism 75, here shown as a shear pin. While shown
as a threaded shear pin, the releasable connector can be any other
suitable releasable connector such as other shear devices, like
shear rings, shafts or the like, or other releasable connectors
such as a collet assembly or other mechanisms known to those
working in the art. Similarly, any other releasable method common
in the art, such as mechanical deformation, physical severing, etc.
can be deployed without departing from the principles of this
invention.
[0047] Alternatively to the embodiment shown in FIG. 5, a
collapsible surface can be provided for the interior surfaces of
the sealing elements 42. A reduced diameter portion of the mandrel
(or sleeve or the like) is moved into alignment with the
collapsible surface. When the collapsible surface collapses to a
smaller diameter, the sealing elements also radially contract,
thereby relaxing the sealing elements. The collapsible surface can
be a split sleeve, a plurality of split rings, wedge shaped
segments, etc. Other mechanical arrangements will be apparent to
those skilled in the art to allow the sealing elements to radially
contract.
[0048] In use, the tool 10 is lowered into a subterranean wellbore
having a casing. Then, the tool 10 is set using a setting assembly,
such as the hydraulic setting assembly 100 shown. While the tool 10
is held in position by a tubing string or the like, hydraulic fluid
is forced by an actuator tool (not shown) through the inlet port
104 into the fluid chamber 106, thereby forcing the piston 102
upward. The upward movement of the piston 102 forces the lower slip
support 65, the lower wedge assembly 30, and the lower slip
assembly 60 upward. Upward movement of the lower wedge assembly 60
compresses the sealing assembly 40. The sealing elements 42 are
moved to a set position, radially expanded and longitudinally
shortened, wherein the sealing elements of the sealing assembly
sealingly engage the wellbore casing. Further, the upper 20 and
lower 60 slip assemblies move longitudinally relative to their
respective wedge assemblies 30 and 50. The slip assemblies, and in
particular the slip elements, are radially expanded into a set
position in gripping engagement with the casing. The timing and
relative motions of these elements of the tool during setting are
controlled by use of shear pins and the like as is known in the art
and not detailed here.
[0049] The tool 10 is then in a set position, the sealing assembly
providing an annular seal between the mandrel and casing, and the
slip assemblies providing a gripping engagement with the casing.
The tool can be left in place in the set position as desired.
During operations in the wellbore, the differential pressure across
the tool may alternate, resulting in the cinching-up described
elsewhere herein.
[0050] To unset and retrieve the tool 10, the mandrel 12 is moved
longitudinally upward relative to the set slip and sealing
assemblies. For example, a retrieving tool is run into the wellbore
on a tubing string or coiled tubing and connected to the upper sub
16 of the tool. In the embodiment illustrated in FIG. 4E, the
mandrel 12 is freed to move longitudinally relative to the slip and
sealing assemblies by cutting the mandrel circumferentially at a
location below the sealing and slip assemblies. A cut 15 is seen at
FIG. 4D. The cutting is done by a cutting tool, such as chemical
cutter. It should be understood, however, that any number of other
suitable means of disconnecting the mandrel can be deployed to cut
the mandrel without departing from the principals of the present
invention. Such other means to disconnect the mandrel may include,
severing by abrasion, laser cutting, shaped-charges, selective
placement of acid or corrosive material, or releasing of one or
more releasable devices such as shear pins, etc. Likewise, the
location of the cut or disconnect can be changed without departing
from the principles of this invention.
[0051] Further upward movement of the mandrel disengages the
sealing elements 42 from the casing by relaxing the compression
forces on the sealing elements 42. The mandrel 12 is moved upwardly
relative to the slip and wedge assemblies, sealing assembly, and
prop assembly. As the mandrel is pulled upward, the groove 78 on
the mandrel 12 moves into alignment with the releasable mechanism
75. The collapsible C-ring 75 collapses, or radially contracts,
into the groove 78, thereby releasing the interlocking toothed
portions 76 and 34 of the releasable connector 75 and upper wedge
assembly 30, respectively. Consequently, the prop member 72 is able
to move relative to the upper wedge assembly. An arm 73 of the prop
member 72 telescopes with a corresponding arm 36 of the upper wedge
assembly 30, as seen in FIG. 3. The prop member 72 moves
longitudinally away from the lower wedge assembly 60, thereby
allowing longitudinal expansion of the sealing elements 42. The
longitudinal expansion of the sealing elements 42 reduces the
compression forces in the sealing assembly and the sealing assembly
radially contracts, disengaging from the casing.
[0052] After the step of disengaging the sealing assembly, the slip
assemblies are disengaged from gripping engagement with the casing.
In the embodiment shown, the upper slip assembly 20 is mechanically
unset by pulling the upper slips off the upper wedge. Further
upward movement of the mandrel 12 moves the lugs 14 into contact
with the upper ends 27 of the slots 24 of the upper slip assembly
20 as seen in FIG. 3A. The lugs 14 pull the upper slip assembly off
the upper wedge assembly 30, thereby unsetting the upper slip
assembly and disengaging the upper slip assembly from the casing,
such that the slip assembly is no longer in gripping engagement
with the casing.
[0053] In the embodiment shown, the lugs contact the closed ends of
the slots simultaneously, thereby pulling the slip elements off the
wedge at approximately the same time. It is to be understood,
however, that simultaneous or sequential unsetting of the slip
elements can be performed. Sequential unsetting of the slip
elements may be preferred where the slip assembly has a plurality
of separated slip elements. Such methods are known in the art and
taught in U.S. patents incorporated herein, for example.
[0054] Further, in the preferred embodiment, the lower slip
assembly is then unset and disengaged from the casing due to
further upward movement of the mandrel 12, which will result in the
lower slip assembly being pulled off the lower wedge assembly 60.
After the compression forces are released in the sealing assembly
and the upper slip assembly is unset, there are no remaining
compression forces maintaining the lower slips on the lower wedge.
Upward movement of the tool will drag the lower slips downward and
off the lower wedge.
[0055] The upper slip assembly is preferably unset and disengaged,
as illustrated, before the lower slip assembly is unset and
disengaged. However, the particular order can be reversed or the
slip assemblies can be disengaged simultaneously.
[0056] Finally, a lower catch mechanism 19, such as shown in FIG.
3D, abuts the lower slip support 65 and the entire tool 10 is
retrieved from the wellbore. The lower end of the tool can
alternately be dropped into the wellbore, but this is not
preferred.
[0057] Finally, the tool 10 is then retrieved from the wellbore by
continuing to pull the toll upward toward the surface.
[0058] A similar method is utilized in relation to the embodiment
of the tool shown in FIG. 4. The tool 10 in FIG. 4 is shown in a
set or engaged position, with the upper slip assembly 20 and lower
slip assembly 60 in a radially expanded position and in gripping
engagement with a casing 8. The mandrel 12 is pulled upward, by a
tubing string, coil tubing, work string or the like. The upward
movement of the mandrel 12 releases the releasable mechanism 75,
here shown as a shear pin. The mandrel 12 is now free to move
longitudinally with respect to the upper and lower slip assemblies,
wedge assemblies, and sealing assembly. A portion of the mandrel 12
acts as the prop member 72 of the prop assembly 70. A first portion
of the mandrel props up, or supports, the interior surface of the
sealing element 42. As the mandrel is pulled upwardly, a reduced
diameter portion 79 of the mandrel is moved into alignment with the
sealing element 42. The sealing element 42 is then able to contract
radially, thereby releasing or relaxing the compressive forces on
the sealing element. The sealing element 42 disengages from the
casing 8. Further upward movement of the mandrel results in
unsetting the upper slip assembly by the methods described above
and not repeated here. The lower slip assembly is also unset, and
the tool is retrieved from the wellbore.
[0059] The wellbore tool used above to describe the principles of
this invention is a packer. Any other wellbore tool set with
opposed slips can be substituted for the packer without departing
from the principles on this invention. Likewise, the wellbore
envisioned in the above description may be used for any purpose,
such as, production, injection, observation, testing, etc., without
departing from this invention's principles.
[0060] The principles of this invention would also apply if the
sealing and/or gripping assemblies were comprised of inflatable
components. While this invention has been described with reference
to illustrative embodiments, this description is not intended to be
construed in a limiting sense. Various modifications and
combinations of the illustrative embodiments as well as other
embodiments of the invention, will be apparent to persons skilled
in the art upon reference to the description. It is, therefore,
intended that the appended claims encompass any such modifications
or embodiments.
* * * * *